Top drive swivel apparatus and method

ABSTRACT

For use with a top drive power unit supported for connection with a well string in a well bore to selectively impart longitudinal and/or rotational movement to the well string, a feeder for supplying a pumpable substance such as cement and the like from an external supply source to the interior of the well string in the well bore without first discharging it through the top drive power unit including a mandrel extending through a sleeve which is sealably and rotatably supported thereon for relative rotation between the sleeve and mandrel. The mandrel and sleeve have flow passages for communicating the pumpable substance from an external source to discharge through the sleeve and mandrel and into the interior of the well string below the top drive power unit. The unit can include a packing injection system, clamp, and novel packing configuration.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation of U.S. patent application Ser. No. 11/831,475,filed Jul. 31, 2007 (issuing as U.S. Pat. No. 7,500,518 on Mar. 10,2009), which was a continuation of U.S. patent application Ser. No.11/371,168, filed Mar. 7, 2006 (now U.S. Pat. No. 7,249,632), which wasa continuation of U.S. patent application Ser. No. 10/658,092, filedSep. 9, 2003 (now U.S. Pat. No. 7,007,753), which claimed priority ofProvisional Patent Application Ser. No. 60/409,177, filed Sep. 9, 2002.Each of these applications are incorporated herein by reference.Priority of each of these applications is hereby claimed.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable

REFERENCE TO A “MICROFICHE APPENDIX”

Not applicable

BACKGROUND

In top drive rigs, the use of a top drive unit, or top drive power unitis employed to rotate drill pipe, or well string in a well bore. Topdrive rigs can include spaced guide rails and a drive frame movablealong the guide rails and guiding the top drive power unit. Thetravelling block supports the drive frame through a hook and swivel, andthe driving block is used to lower or raise the drive frame along theguide rails. For rotating the drill or well string, the top drive powerunit includes a motor connected by gear means with a rotatable memberboth of which are supported by the drive frame.

During drilling operations, when it is desired to “trip” the drill pipeor well string into or out of the well bore, the drive frame can belowered or raised. Additionally, during servicing operations, the drillstring can be moved longitudinally into or out of the well bore.

The stem of the swivel communicates with the upper end of the rotatablemember of the power unit in a manner well known to those skilled in theart for supplying fluid, such as a drilling fluid or mud, through thetop drive unit and into the drill or work string. The swivel allowsdrilling fluid to pass through and be supplied to the drill or wellstring connected to the lower end of the rotatable member of the topdrive power unit as the drill string is rotated and/or moved up anddown.

Top drive rigs also can include elevators are secured to and suspendedfrom the frame, the elevators being employed when it is desired to lowerjoints of drill string into the well bore, or remove such joints fromthe well bore.

At various times top drive operations, beyond drilling fluid, requirevarious substances to be pumped downhole, such as cement, chemicals,epoxy resins, or the like. In many cases it is desirable to supply suchsubstances at the same time as the top drive unit is rotating and/ormoving the drill or well string up and/or down, but bypassing the topdrive's power unit so that the substances do not damage/impair the unit.Additionally, it is desirable to supply such substances withoutinterfering with and/or intermittently stopping longitudinal and/orrotational movement by the top drive unit of the drill or well string.

A need exists for a device facilitating insertion of various substancesdownhole through the drill or well string, bypassing the top drive unit,while at the same time allowing the top drive unit to rotate and/or movethe drill or well string.

One example includes cementing a string of well bore casing. In somecasing operations it is considered good practice to rotate the string ofcasing when it is being cemented in the wellbore. Such rotation isbelieved to facilitate better cement distribution and spread inside theannular space between the casing's exterior and interior of the wellbore. In such operations the top drive unit can be used to both supportand continuously rotate/intermittently reciprocate the string of casingwhile cement is pumped down the string's interior. During this time itis desirable to by-pass the top drive unit to avoid possible damage toany of its portions or components.

The following U.S. Patents are incorporated herein by reference: U.S.Pat. No. 4,722,389.

While certain novel features of this invention shown and described beloware pointed out in the annexed claims, the invention is not intended tobe limited to the details specified, since a person of ordinary skill inthe relevant art will understand that various omissions, modifications,substitutions and changes in the forms and details of the deviceillustrated and in its operation may be made without departing in anywayfrom the spirit of the present invention. No feature of the invention iscritical or essential unless it is expressly stated as being “critical”or “essential.”

BRIEF SUMMARY

The apparatus of the present invention solves the problems confronted inthe art in a simple and straightforward manner. The invention hereinbroadly relates to an assembly having a top drive arrangement forrotating and longitudinally moving a drill or well string. In oneembodiment the present invention includes a swivel apparatus, the swivelgenerally comprising a mandrel and a sleeve, the swivel being especiallyuseful for top drive rigs.

The sleeve can be rotatably and sealably connected to the mandrel. Theswivel can be incorporated into a drill or well string and enablingstring sections both above and below the sleeve to be rotated inrelation to the sleeve. Additionally, the swivel provides a flow pathbetween the exterior of the sleeve and interior of the mandrel while thedrill string is being moved in a longitudinal direction (up or down)and/or being rotated/reciprocated. The interior of the mandrel can befluidly connected to the longitudinal bore of casing or drill stringthus providing a path from the sleeve to the interior of thecasing/drill string.

In one embodiment an object of the present invention is to provide amethod and apparatus for servicing a well wherein a swivel is connectedto and below a top drive unit for conveying pumpable substances from anexternal supply through the swivel for discharge into the well string,but bypassing the top drive unit.

In another embodiment of the present invention is provided a method ofconducting servicing operations in a well bore, such as cementing,comprising the steps of moving a top drive unit longitudinally and/orrotationally to provide longitudinal movement and/orrotation/reciprocation in the well bore of a well string suspended fromthe top drive unit, rotating the drill or well string and supplying apumpable substance to the well bore in which the drill or well string ismanipulated by introducing the pumpable substance at a point below thetop drive power unit and into the well string.

In other embodiments of the present invention a swivel placed below thetop drive unit can be used to perform jobs such as spotting pills,squeeze work, open formation integrity work, kill jobs, fishing tooloperations with high pressure pumps, sub-sea stack testing, rotation ofcasing during side tracking, and gravel pack or frack jobs. In stillother embodiments a top drive swivel can be used in a method of pumpingloss circulation material (LCM) into a well to plug/seal areas ofdownhole fluid loss to the formation and in high speed milling jobsusing cutting tools to address down hole obstructions. In otherembodiments the top drive swivel can be used with free point indicatorsand shot string or cord to free stuck pipe where pumpable substances arepumped downhole at the same time the downhole string/pipe/free pointindicator is being rotated and/or reciprocated. In still otherembodiments the top drive swivel can be used for setting hook wallpackers and washing sand.

In still other embodiments the top drive swivel can be used for pumpingpumpable substances downhole when repairs/servicing is being done to thetop drive unit and rotation of the downhole drill string is beingaccomplished by the rotary table. Such use for rotation and pumping canprevent sticking/seizing of the drill string downhole. In thisapplication safety valves, such as TIW valves, can be placed above andbelow the top drive swivel to enable routing of fluid flow and to ensurewell control.

The drawings constitute a part of this specification and includeexemplary embodiments to the invention, which may be embodied in variousforms.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

For a further understanding of the nature, objects, and advantages ofthe present invention, reference should be had to the following detaileddescription, read in conjunction with the following drawings, whereinlike reference numerals denote like elements and wherein:

FIG. 1 is a schematic view showing a top drive rig with one embodimentof a top drive swivel incorporated in the drill string;

FIG. 2 is a schematic view of one embodiment of a top drive swivel;

FIG. 3 is a sectional view of a mandrel which can be incorporated in thetop drive swivel of FIG. 2;

FIG. 4 is a sectional view of a sleeve which can be incorporated intothe top drive swivel of FIG. 2;

FIG. 5 is a right hand side view of the sleeve of FIG. 4;

FIG. 6 is a sectional view of the top drive swivel of FIG. 2;

FIG. 6A is a sectional view of the packing unit shown in FIG. 6;

FIG. 6B is a top view of the packing injection ring shown in FIGS. 6 and6A;

FIG. 6C is a side view section of the packing injection ring shown inFIG. 6B;

FIG. 7 is a top view of a clamp which can be incorporated into the topdrive swivel of FIG. 2;

FIG. 8 is a side view of the clamp of FIG. 7;

FIG. 9 is a perspective view and partial sectional view of the top driveswivel shown in FIG. 2.

DETAILED DESCRIPTION

Detailed descriptions of one or more preferred embodiments are providedherein. It is to be understood, however, that the present invention maybe embodied in various forms. Therefore, specific details disclosedherein are not to be interpreted as limiting, but rather as a basis forthe claims and as a representative basis for teaching one skilled in theart to employ the present invention in any appropriate system, structureor manner.

FIG. 1 is a schematic view showing a top drive rig 1 with one embodimentof a top drive swivel 30 incorporated into drill string 20. FIG. 1 isshows a rig 1 having a top drive unit 10. Rig 5 comprises supports16,17; crown block 2; traveling block 4; and hook 5. Draw works 11 usescable 12 to move up and down traveling block 4, top drive unit 10, anddrill string 20. Traveling block 4 supports top drive unit 10. Top driveunit 10 supports drill string 20.

During drilling operations, top drive unit 10 can be used to rotatedrill string 20 which enters wellbore 14. Top drive unit 10 can ridealong guide rails 15 as unit 10 is moved up and down. Guide rails 15prevent top drive unit 10 itself from rotating as top drive unit 10rotates drill string 20. During drilling operations drilling fluid canbe supplied downhole through drilling fluid line 8 and gooseneck 6.

At various times top drive operations, beyond drilling fluid, requiresubstances to be pumped downhole, such as cement, chemicals, epoxyresins, or the like. In many cases it is desirable to supply suchsubstances at the same time as top drive unit 10 is rotating and/ormoving drill or well string 20 up and/or down and bypassing top driveunit 10 so that the substances do not damage/impair top drive unit 10.Additionally, it is desirable to supply such substances withoutinterfering with and/or intermittently stopping longitudinal and/orrotational movements of drill or well string 20 being moved/rotated bytop drive unit 10. This can be accomplished by using top drive swivel30.

Top drive swivel 30 can be installed between top drive unit 10 and drillstring 20. One or more joints of drill pipe 18 can be placed between topdrive unit 10 and swivel 30. Additionally, a valve can be placed betweentop drive swivel 30 and top drive unit 10. Pumpable substances can bepumped through hose 31, swivel 30, and into the interior of drill string20 thereby bypassing top drive unit 10. Top drive swivel 30 ispreferably sized to be connected to drill string 20 such as 4½ inch IFAPI drill pipe or the size of the drill pipe to which swivel 30 isconnected to. However, cross-over subs can also be used between topdrive swivel 30 and connections to drill string 20.

FIG. 2 is a schematic view of one embodiment of a top drive swivel 30.Top drive swivel 30 can be comprised of mandrel 40 and sleeve 150.Sleeve 150 is rotatably and sealably connected to mandrel 30.Accordingly, when mandrel 40 is rotated, sleeve 150 can remainstationary to an observer insofar as rotation is concerned. As will bediscussed later inlet 200 of sleeve 150 is and remains fluidly connectedto a the central longitudinal passage 90 of mandrel 40. Accordingly,while mandrel 40 is being rotated and/or moved up and down pumpablesubstances can enter inlet 20 and exit central longitudinal passage 90at lower end 60 of mandrel 40.

FIG. 3 is a sectional view of mandrel 40 which can be incorporated inthe top drive swivel 30. Mandrel 40 is comprised of upper end 50 andlower end 60. Central longitudinal passage 90 extends from upper end 50through lower end 60. Lower end 60 can include a pin connection or anyother conventional connection. Upper end 50 can include box connection70 or any other conventional connection. Mandrel 40 can in effect becomea part of drill string 20. Sleeve 150 fits over mandrel 40 and becomesrotatably and sealably connected to mandrel 40. Mandrel 40 can includeshoulder 100 to supper sleeve 150. Mandrel 40 can include one or moreradial inlet ports 140 fluidly connecting central longitudinal passage90 to recessed area 130. Recessed area 130 preferably forms acircumferential recess along the perimeter of mandrel 40 and betweenpacking support areas 131,132. In such manner recessed area will remainfluidly connected with radial passage 190 and inlet 200 of sleeve 150(see FIGS. 4, 6).

To reduce friction between mandrel 40 and packing units 305,415 (FIG. 6)and increase the life expectancy of packing units 305, 415, packingsupport areas 131, 132 can be coated and/or sprayed welded with amaterials of various compositions, such as hard chrome, nickel/chrome ornickel/aluminum (95 percent nickel and 5 percent aluminum) A materialwhich can be used for coating by spray welding is the chrome alloy TAFA95 MX Ultrahard Wire (Armacor M) manufactured by TAFA Technologies,Inc., 146 Pembroke Road, Concord N.H. TAFA 95 MX is an alloy of thefollowing composition: Chromium 30 percent; Boron 6 percent; Manganese 3percent; Silicon 3 percent; and Iron balance. The TAFA 95 MX can becombined with a chrome steel. Another material which can be used forcoating by spray welding is TAFA BONDARC WIRE-75B manufactured by TAFATechnologies, Inc. TAFA BONDARC WIRE-75B is an alloy containing thefollowing elements: Nickel 94 percent; Aluminum 4.6 percent; Titanium0.6 percent; Iron 0.4 percent; Manganese 0.3 percent; Cobalt 0.2percent; Molybdenum 0.1 percent; Copper 0.1 percent; and Chromium 0.1percent. Another material which can be used for coating by spray weldingis the nickel chrome alloy TAFALOY NICKEL-CHROME-MOLY WIRE-71Tmanufactured by TAFA Technologies, Inc. TAFALOY NICKEL-CHROME-MOLYWIRE-71T is an alloy containing the following elements: Nickel 61.2percent; Chromium 22 percent; Iron 3 percent; Molybdenum 9 percent;Tantalum 3 percent; and Cobalt 1 percent. Various combinations of theabove alloys can also be used for the coating/spray welding. Packingsupport areas 131, 132 can also be coated by a plating method, such aselectroplating. The surface of support areas 131, 132 can beground/polished/finished to a desired finish to reduce friction and wearbetween support areas 131, 132 and packing units 305, 415.

FIG. 4 is a sectional view of sleeve 150 which can be incorporated intotop drive swivel 30. FIG. 5 is a right hand sectional view of sleeve 150taken along the lines 4-4. Sleeve 150 can include central longitudinalpassage 180 extending from upper end 160 through lower end 170. Sleeve150 can also include radial passage 190 and inlet 200. Inlet 200 can beattached by welding or any other conventional type method of fasteningsuch as a threaded connection. If welded the connection is preferablyheat treated to remove residual stresses created by the weldingprocedure. Also shown is protruding section 155 along with upper andlower shoulders 156,157. Lubrication port 210 can be included to providelubrication for interior bearings. Packing ports 220, 230 can also beincluded to provide the option of injecting packing material into thepacking units 305,415 (see FIG. 6). A protective cover 240 can be placedaround packing port 230 to protect packing injector 235 (see FIG. 6).Optionally, a second protective cover can be placed around packing port220, however, it is anticipated that protection will be provided byclamp 600 and inlet 200. Sleeve 150 can include peripheral groove 205for attachment of clamp 600. Additionally, key way 206 can be providedfor insertion of a key 700. FIG. 5 illustrates how central longitudinalpassage 180 is fluidly connected to inlet 200 through radial passage190. It is preferred that welding be performed using PreferredIndustries Welding Procedure number T3, 1550REV-A 4140HT (285/311 bhn)RMT to 4140 HT (285/311 bhn(RMT) It is also preferred that welds beX-ray tested, magnetic particle tested, and stress relieved.

FIG. 6 is a sectional view of the assembled top drive swivel 30 of FIG.2. As can be seen sleeve 150 slides over mandrel 40. Bearings 145, 146rotatably connect sleeve 150 to mandrel 40. Bearings 145, 146 arepreferably thrust bearings although many conventionally availablebearing will adequately function, including conical and ball bearings.Packing units 305, 415 sealingly connect sleeve 150 to mandrel 40. Inlet200 of sleeve 150 is and remains fluidly connected to centrallongitudinal passage 90 of mandrel 40. Accordingly, while mandrel 40 isbeing rotated and/or moved up and down pumpable substances can enterinlet 200 and exit central longitudinal passage 90 at lower end 60 ofmandrel 40. Recessed area 130 and protruding section 155 form aperipheral recess between mandrel 40 and sleeve 150. The fluid pathwayfrom inlet 200 to outlet at lower end 60 of central longitudinal passage90 is as follows: entering inlet 200 (arrow 201); passing through radialpassage 190 (arrow 202); passing through recessed area 130 (arrow 202);passing through one of the plurality of radial inlet ports 140 (arrow202), passing through central longitudinal passage 90 (arrow 203); andexiting mandrel 40 via lower end 60 at pin connection 80 (arrows 204,205).

FIG. 6A shows a blown up schematic view of packing unit 305. Packingunit 305 can comprise packing end 320; packing ring 330, packing ring340, packing lubrication ring 350, packing end 360, packing ring 370,packing ring 380, packing ring 390, packing ring 400, and packing end410. Packing unit 305 sealing connects mandrel 40 and sleeve 150.Packing unit 305 can be encased by packing retainer nut 310 and shoulder156 of protruding section 155. Packing retainer nut 310 can be a ringwhich threadably engages sleeve 150 at threaded area 316. Packingretainer nut 310 and shoulder 156 squeeze packing unit 305 to obtain agood seal between mandrel 40 and sleeve 150. Set screw 315 can be usedto lock packing retainer nut 310 in place and prevent retainer nut 310from loosening during operation. Set screw 315 can be threaded into bore314 and lock into receiving area 317 on sleeve 150. Packing unit 415 canbe constructed substantially similar to packing unit 305. The materialsfor packing unit 305 and packing unit 415 can be similar.

Packing end 320 is preferably a bronze female packing end. Packing ring330 is preferably a “Vee” packing ring—Teflon such as that supplied byCDI part number 0500700-VS-720 Carbon Reflon (having 2 percent carbon).Packing ring 340 is preferably a “Vee” packing ring—Rubber such as thatsupplied by CDI part number 0500700-VS-850NBR Aramid. Packinglubrication ring 350 is described below in the discussion regardingFIGS. 6B and 6C. Packing end 360 preferably a bronze female packing end.Packing ring 370 is preferably a “Vee” packing ring—Teflon such as thatsupplied by CDI part number 0500700-VS-720 Carbon Reflon (having 2percent carbon). Packing ring 380 is preferably a “Vee” packingring—Rubber such as that supplied by CDI part number 0500700-VS-850NBRAramid. Packing ring 390 is preferably a “Vee” packing ring—Teflon suchas that supplied by CDI part number 0500700-VS-720 Carbon Reflon (having2 percent carbon). Packing ring 400 is preferably a “Vee” packingring—Rubber such as that supplied by CDI part number 0500700-VS-850NBRAramid. Packing end 410 is preferably a bronze male packing ring.Various alternative materials for packing rings can be used such asstandard chevron packing rings of standard packing materials. Bronzerings preferably meet or exceed an SAE 660 standard.

A packing injection option can be provided for top drive swivel 30.Injection fitting 225 can be used to inject additional packing materialsuch as teflon into packing unit 305. Head 226 for injection fitting 225can be removed and packing material can then be inserting into fitting225. Head 226 can then be screwed back into injection fitting 225 whichwould push packing material through fitting 225 and into packing port220. The material would then be pushed into packing ring 350. Packingring 350 can comprise radial port 352 and transverse port 351. Thematerial would proceed through radial port 352 and exit throughtransverse port 351. The material would tend to push out and squeezepacking rings 340, 330, 320 and packing rings 360, 370, 380, 390, 400tending to create a better seal between packing unit 305 with mandrel 40and sleeve 150. The interaction between injection fitting 235 andpacking unit 415 can be substantially similar to the interaction betweeninjection fitting 225 and packing unit 305. A conventionally availablematerial which can be used for packing injection fittings 225, 235 isDESCO™ 625 Pak part number 6242-12 in the form of a 1 inch by ⅜ inchstick and distributed by Chemola Division of South Coast Products, Inc.,Houston, Tex. In FIG. 6, injection fitting 235 is shown ninety degreesout of phase and, is preferably located as shown in FIG. 9.

Injection fittings 225, 235 have a dual purpose: (a) provide an operatora visual indication whether there has been any leakage past eitherpacking units 305, 415 and (b) allow the operator to easily injectadditional packing material and stop seal leakage without removing topdrive swivel 30 from drill string 20.

FIGS. 6B and 6C shows top and side views of packing injection ring 350.Packing injection ring 350 includes a male end 355 at its top and a flatend 356 at its rear. Ring 350 includes peripheral groove 353 around itsperimeter. Optionally, ring 350 can include interior groove along itsinterior. A plurality of transverse ports 351,351′, 351″, 351″′, etc.extending from male end 355 to flat end 356 can be included and can beevenly spaced along the circumference of ring 350. A plurality of radialports 352, 352′, 352″, 352′″, etc. can be included extending fromperipheral groove 353 and respectively intersecting transverse ports351,351′, 351″, 351″′, etc. Preferably, the radial ports can extend fromperipheral groove 353 through interior groove 354.

Retainer nut 800 can be used to maintain sleeve 150 on mandrel 40.Retainer nut 800 can threadably engage mandrel 40 at threaded area 801.Set screw 890 can be used to lock in place retainer nut 800 and preventnut 800 from loosening during operation. Set screw 890 threadablyengages retainer nut 800 through bore 900 and sets in one of a pluralityof receiving portions 910 formed in mandrel 40. Retaining nut 800 canalso include grease injection fitting 880 for lubricating bearing 145.Wiper ring 271 set in area 270 protects against dirt and other itemsfrom entering between the sleeve 150 and mandrel 40. Grease ring 291 setin area 290 holds in lubricant for bearing 145.

Bearing 146 can be lubricated through grease injection fitting 211 andlubrication port 210. Bearing 145 can be lubricated through greaseinjection fitting 881 and lubrication port 880.

FIG. 7 is a top view of clamp 600 which can be incorporated into topdrive swivel 30. FIG. 8 is a side view of clamp 600. Clamp 600 comprisesfirst portion 610 and second portion 620. First and second portions 610,620 can be removably attached by fasteners 670, 680. Clamp 600 fits ingroove 605 of sleeve 150 (FIG. 6). Key 700 can be included in keyway690. A corresponding keyway 691 is included in sleeve 150 of top driveswivel 30. Keyways 690, 691 and key 700 prevent clamp 600 from rotatingrelative to sleeve 150. A second key 720 can be installed in keyways710, 711. Shackles 650, 660 can be attached to clamp 600 to facilitatehanding top drive swivel 30 when clamp 600 is attached. Torque arms 630,640 can be included to allow attachment of clamp 600 (and sleeve 150) toa stationary part of top drive rig 1 and prevent sleeve 150 fromrotating while drill string 20 is being rotated by top drive 10 (and topdrive swivel 30 is installed in drill string 20). Torque arms 630, 640are provided with holes for attaching restraining shackles. Restrainedtorque arms 630, 640 prevent sleeve 150 from rotating while mandrel 40is being spun. Otherwise, frictional forces between packing units 305,415 and packing support areas 131, 135 of rotating mandrel 40 would tendto also rotate sleeve 150. Clamp 600 is preferably fabricated from 4140heat treated steel being machined to fit around sleeve 150.

FIG. 9 is an overall perspective view (and partial sectional view) oftop drive swivel 30. Sleeve 150 is shown rotatably connected to mandrel40. Bearings 145, 146 allow sleeve 150 to rotate in relation to mandrel40. Packing units 305, 415 sealingly connect sleeve 150 to mandrel 40.Retaining nut 800 retains sleeve 150 on mandrel 40. Inlet 200 of sleeve150 is fluidly connected to central longitudinal passage 90 of mandrel40. Accordingly, while mandrel 40 is being rotated and/or moved up anddown pumpable substances can enter inlet 200 and exit centrallongitudinal passage 90 at lower end 60 of mandrel 40. Recessed area 130and protruding section 155 form a peripheral recess between mandrel 40and sleeve 150. The fluid pathway from inlet 200 to outlet at lower end60 of central longitudinal passage 90 is as follows: entering inlet 200;passing through radial passage 190; passing through recessed area 130;passing through one of the plurality of radial inlet ports 40; passingthrough central longitudinal passage 90; and exiting mandrel 40 throughcentral longitudinal passage 90 at lower end 60 and pin connection 80.In FIG. 9, injection fitting 225 is shown ninety degrees out of phaseand, for protection, is preferably located between inlet 200 and clamp600.

Mandrel 40 takes substantially all of the structural load from drillstring 20. The overall length of mandrel 40 is preferably 52 and 5/16inches. Mandrel 40 can be machined from a single continuous piece ofheat treated steel bar stock. NC50 is preferably the API Tool JointDesignation for the box connection 70 and pin connection 80. Such tooljoint designation is equivalent to and interchangeable with 4½ inch IF(Internally Flush), 5 inch XH (Extra Hole) and 5½ inch DSL (DoubleStream Line) connections. Additionally, it is preferred that the boxconnection 70 and pin connection 80 meet the requirements of APIspecifications 7 and 7G for new rotary shouldered tool joint connectionshaving 6⅝ inch outer diameter and a 2¾ inch inner diameter. The Strengthand Design Formulas of API 7G-Appendix A provides the following loadcarrying specification for mandrel 40 of top drive swivel 30: (a) 1,477pounds tensile load at the minimum yield stress; (b) 62,000 foot-poundstorsion load at the minimum torsional yield stress; and (c) 37,200foot-pounds recommended minimum make up torque. Mandrel 40 can bemachined from 4340 heat treated bar stock.

Sleeve 150 is preferably fabricated from 4140 heat treated roundmechanical tubing having the following properties: (120,000 psi minimumtensile strength, 100,000 psi minimum yield strength, and 285/311Brinell Hardness Range). The external diameter of sleeve 150 ispreferably about 11 inches. Sleeve 150 preferably resists high internalpressures of fluid passing through inlet 200. Preferably top driveswivel 30 with sleeve 150 will withstand a hydrostatic pressure test of12,500 psi. At this pressure the stress induced in sleeve 150 ispreferably only about 24.8 percent of its material's yield strength. Ata preferable working pressure of 7,500 psi, there is preferably a 6.7:1structural safety factor for sleeve 150.

To minimize flow restrictions through top drive swivel 30, large openareas are preferred. Preferably each area of interest throughout topdrive swivel 30 is larger than the inlet service port area 200. Inlet200 is preferably 3 inches having a flow area of 4.19 square inches. Theflow area of the annular space between sleeve 150 and mandrel 40 ispreferably 20.81 square inches. The flow area through the plurality ofradial inlet ports 140 is preferably 7.36 square inches. The flow areathrough central longitudinal bore 90 is preferably 5.94 square inches.

The following is a list of reference numerals:

LIST FOR REFERENCE NUMERALS (Part No.) (Description) Reference NumeralDescription 1 rig 2 crown block 3 cable means 4 travelling block 5 hook6 gooseneck 7 swivel 8 drilling fluid line 10 top drive unit 11 drawworks 12 cable 13 rotary table 14 well bore 15 guide rail 16 support 17support 18 drill pipe 19 drill string 20 drill string or work string 30swivel 31 hose 40 swivel mandrel 50 upper end 60 lower end 70 boxconnection 80 pin connection 90 central longitudinal passage 100shoulder 101 outer surface of shoulder 102 upper surface of shoulder 110interior surface 120 external surface (mandrel) 130 recessed area 131packing support area 132 packing support area 140 radial inlet ports (aplurality) 145 bearing (preferably combination 6.875 inch bearing cone,Timken Part number 67786, and 9.75 inch bearing cup bearing cup, Timkenpart number 67720) 146 bearing (preferably combination 7 inch bearingcone, Timken Part number 67791, and 9.75 inch bearing cup bearing cup,Timken part number 67720) 150 swivel sleeve 155 protruding section 156shoulder 157 shoulder 158 packing support area 159 packing support area160 upper end 170 lower end 180 central longitudinal passage 190 radialpassage 200 inlet 201 arrow 202 arrow 203 arrow 204 arrow 205 peripheralgroove 206 key way 210 lubrication port 211 grease injection fitting(preferably grease zerk (¼ - 28 td. in. streight, mat.-monel Alemitepart number 1966-B) 220 packing port 225 injection fitting (preferablypacking injection fitting (10,000 psi) Vesta - PGI Manufacturing partnumber PF10N4- 10) (alternatively Pressure Relief Tool for packinginjection fitting Vesta - PGI Manufacturing part number PRT - PIF 12-20)226 head 230 packing port 235 injection fitting (preferably packinginjection fitting (10,000 psi) Vesta - PGI Manufacturing part numberPF10N4- 10) (alternatively Pressure Relief Tool for packing injectionfitting Vesta - PGI Manufacturing part number PRT - PIF 12-20) 240 cover250 upper shoulder 260 lower shoulder 270 area for wiper ring 271 wiperring (preferably Parker part number 959-65) 280 area for wiper ring 281wiper ring (preferably Parker part number 959-65) 290 area for greasering 291 grease ring (preferably Parker part number 2501000 StandardPolypak) 300 area for grease ring 301 grease ring (preferably Parkerpart number 2501000 Standard Polypak) 305 packing unit 310 packingretainer nut 314 bore for set screw 315 set screw for packing retainernut 316 threaded area 317 set screw for receiving area 320 packing end330 packing ring 340 packing ring 350 packing injection ring 351transverse port 352 radial port 353 peripheral groove 354 interiorgroove 355 male end 356 flat end 360 packing end 370 packing ring 380packing ring 390 packing ring 400 packing ring 410 packing end 415packing unit 420 packing retainer nut 425 set screw for packing retainernut 430 packing end 440 packing ring 450 packing ring 460 packinglubrication ring 470 packing end 480 packing ring 490 packing ring 500packing ring 510 packing ring 520 packing end 600 clamp 605 groove 610first portion 620 second portion 630 torque arm 640 torque arm 650shackle 660 shackle 670 fastener 680 fastener 690 keyway 691 keyway 700key 710 keyway 711 keyway 720 key 730 peripheral groove 800 retainingnut 801 threaded area 810 outer surface 820 inclined portion 830 bore840 inner surface 850 threaded portion 860 upper surface 870 bottomsurface 880 lubrication port 881 grease injection fitting (preferablygrease zerk (¼ - 28 td. in. streight, mat.-monel Alemite part number1966-B) 890 set screw 900 bore for set screw 910 receiving portion forset screw

All measurements disclosed herein are at standard temperature andpressure, at sea level on Earth, unless indicated otherwise. Allmaterials used or intended to be used in a human being arebiocompatible, unless indicated otherwise.

It will be understood that each of the elements described above, or twoor more together may also find a useful application in other types ofmethods differing from the type described above. Without furtheranalysis, the foregoing will so fully reveal the gist of the presentinvention that others can, by applying current knowledge, readily adaptit for various applications without omitting features that, from thestandpoint of prior art, fairly constitute essential characteristics ofthe generic or specific aspects of this invention set forth in theappended claims. The foregoing embodiments are presented by way ofexample only; the scope of the present invention is to be limited onlyby the following claims.

1. A method of using a top drive swivel comprising the steps of: (a)providing a top drive swivel insertable into a drill or work stringcomprising: (i) a mandrel having upper and lower end sections andconnected to and rotatable with upper and lower drill or work stringsections, the mandrel including a longitudinal passage forming acontinuation of a passage in the drill or work string sections; (ii) asleeve having a longitudinal sleeve passage, the sleeve being rotatablyconnected to the mandrel; (iii) a seal between upper and lower endportions of the mandrel and sleeve, the seal preventing leakage of fluidbetween the mandrel and sleeve; (iv) the sleeve comprising an inletport; (v) the mandrel comprising a plurality of spaced apart radialports in fluid communication with both the inlet port and thelongitudinal passage to supply pressurized fluid from the inlet port tothe longitudinal passage and in the passage in drill or work stringsections; and (vi) a clamp, the clamp being connectable to the sleeve;(b) attaching the swivel to the drill or work string of a rig; and (c)performing a job on the rig with the swivel.
 2. The method of claim 1,wherein in step “a” the sleeve further comprises a peripheral groove,the clamp fitting in the groove, and wherein the clamp comprises firstand second portions, the first and second portions being detachablyconnectable to each other.
 3. The method of claim 2, wherein the clampand sleeve further comprise a key, the key fitting between the clamp andsleeve and restricting relative rotational movement between the clampand sleeve.
 4. The method of claim 3, wherein the clamp and sleevefurther comprise a second key, the second key fitting between the clampand sleeve.
 5. The method of claim 1, wherein the clamp comprises atleast one torque arm.
 6. The method of claim 1, wherein in step “c” thejob includes spotting pills.
 7. The method of claim 1, wherein in step“c” the job includes squeeze work.
 8. The method of claim 1, wherein instep “c” the job includes open formation integrity work.
 9. The methodof claim 1, wherein in step “c” the job includes kill jobs.
 10. Themethod of claim 1, wherein in step “c” the job includes fishing tooloperations with high pressure pumps.
 11. The method of claim 1, whereinin step “c” the job includes sub-sea stack testing.
 12. The method ofclaim 1, wherein in step “c” the job includes rotation of casing duringside tracking.
 13. The method of claim 1, wherein in step “c” the jobincludes gravel pack or frack jobs.
 14. The method of claim 1, whereinin step “c” the job includes a method of pumping loss circulationmaterial into a well to plug/seal areas of downhole fluid loss to theformation.
 15. The method of claim 1, wherein in step “c” the jobincludes free point indicators and shot string or cord to free stuckpipe with pumpable substance being pumped downhole.
 16. The method ofclaim 1, wherein in step “c” the job includes servicing a top drive unitwhile pumpable substances are pumped through the swivel and downhole.